The removal of the acid gas components carbon dioxide and hydrogen sulfide from natural gas is of considerable importance inasmuch as these components can be present to a significant extent. Carbon dioxide and hydrogen sulfide contamination lower the heating value of the natural gas and cause corrosion concerns and increase the transportation cost based on unit heating value. For these reasons carbon dioxide commonly requires removal to a level of 2% or less and hydrogen sulfide must often be removed to levels of 4 ppm or less for pipeline transportation of natural gas. These components also have a high freezing point and for this reason must be almost completely removed from natural gas prior to processing in liquefied natural gas (LNG) plants.
Methods heretofore known for purification of natural gas, in particular, acid gas removal may be divided roughly into three classifications:                (a) Methods involving amine adsorption treatment where the amine forms weak bonds with the acid gases at relatively low processing temperatures and (usually) high pressure. The rich amine solvent is regenerated by decreasing its pressure and increasing its temperature in an amine stripper. The acid gas components are then removed.        (b) By adsorption using a physical solvent at relatively low temperatures and relatively high pressures wherein the solubility of the acid gas components is greater than that of light hydrocarbons. The physical solvent is generally regenerated by pressure reduction causing the dissolved gases to flash from the solvent.        (c) Miscellaneous processes involving selective diffusion of the gases through a series of polymeric membranes, wherein the acid gas-contaminated natural gas feed is introduced at high pressure and the acid gas components due to higher solubility and diffusion principles permeate across the membrane from high pressure to low pressure held on the permeate side of the membrane.        
A principal disadvantage of the amine treatment adsorption is that water will be reintroduced into the natural gas stream by the aqueous amine solvent. Further, the use of solvents, in particular, volatile organic solvents is being discouraged if not out right banned by government agencies in order to reduce both water and air pollutions.
For smaller volume applications, especially where gas flows are less than five to ten million cubic feet per day, considerable attention has been given to the development of pressure swing adsorption (PSA) processes for removal of gaseous impurities such as CO2.
Numerous patents describe PSA processes for separating carbon dioxide from methane or other gases. One of the earlier patents in this area is U.S. Pat. No. 3,751,878, which describes a PSA system using a zeolite molecular sieve that selectively adsorbs CO2 from a low quality natural gas stream operating at a pressure of 1000 psia, and a temperature of 300° F. The system uses carbon dioxide as a purge to remove some adsorbed methane from the zeolite and to purge methane from the void space in the column. U.S. Pat. No. 4,077,779, describes the use of a carbon molecular sieve that adsorbs CO2 selectively over hydrogen or methane. After the adsorption step, a high pressure purge with CO2 is followed by pressure reduction and desorption of CO2 followed by a rinse at an intermediate pressure with an extraneous gas such as air. The column is then subjected to vacuum to remove the extraneous gas and any remaining CO2.
U.S. Pat. No. 4,770,676, describes a process combining a temperature swing adsorption (TSA) process with a PSA process for the recovery of methane from landfill gas. The TSA process removes water and minor impurities from the gas, which then goes to the PSA system, which is similar to that described in U.S. Pat. No. 4,077,779 above, except the external rinse step has been eliminated. CO2 from the PSA section is heated and used to regenerate the TSA section. U.S. Pat. No. 4,857,083, claims an improvement over U.S. Pat. No. 4,077,779 by eliminating the external rinse step and using an internal rinse of secondary product gas (CO2) during blowdown, and adding a vacuum for regeneration. The preferred type of adsorbent is activated carbon, but can be a zeolite such as 5A, molecular sieve carbons, silica gel, activated alumina or other adsorbents selective for carbon dioxide and gaseous hydrocarbons other than methane.
As above noted, it is well-known to remove acid gases such as hydrogen sulfide and carbon dioxide from natural gas streams using an amine system wherein the acid gases are scrubbed from the feed with an aqueous amine solvent with the solvent subsequently stripped of the carbon dioxide or other acid gases with steam. These systems are widely used in industry with over 600 large units positioned in natural gas service in the U.S. The amine solvent suppliers compete vigorously and the amines used range from diethanol amine (DEA) to specialty formulations allowing smaller equipment and operating costs while incurring a higher solvent cost. These systems are well accepted although they are not very easy to operate. Keeping the amine solvents clean can be an issue.
Again, a disadvantage to using aqueous amines is that the natural gas product of an aqueous amine system is water saturated. Accordingly, dehydration typically using glycol absorption would be required on the product stream after the carbon dioxide has been removed adding operational and capital costs to the purification process.
A further concern with amine treating of natural gas containing heavy hydrocarbons is that the heavy hydrocarbons can cause foaming of the amine solvent. Foaming of the solvent is undesired as it reduces the capacity of the system and can result in carryover of the solvent into the product gas stream.
The majority of the market supply of C2 and C3+ hydrocarbons are extracted from natural gas. For this reason these components are commonly termed natural gas liquids (NGLs). The removal of the C3+ hydrocarbons from natural gas is accomplished in three alternative routes.
In the first and oldest method, heavy oil is contacted with natural gas such that the lean oil wash adsorbs C3+ components into the liquid. These components are then stripped from the oil and eventually recovered as a separate product. More recent designs use refrigerated oil but overall this technology is considered outdated. A second method of recovery of C3+ hydrocarbons is through a refrigeration system where the natural gas feed is chilled to temperatures typically in the range of −30° F. and the C3+ components are substantially condensed from the natural gas stream. A more efficient, though more expensive, method and means to recover ethane as well, is generally applied to large gas flows where a turbo-expander plant expands the natural gas to a lower pressure. This expansion causes a substantial drop in the temperature of the natural gas stream. Once more, C3+ hydrocarbons are removed. As a general rule turbo-expander plants are favored where ethane recovery is desired or higher levels of C3+ liquids recovery is justified. These plants are expensive, especially for recompression. All of the routes for liquid recovery are fairly expensive in capital and require considerable power for either refrigeration or recompression.
Hydrocarbons are also commonly removed from natural gas to prevent the condensation of liquids in pipeline transmission systems and pipelines commonly impose a dew point specification to prevent the condensation of the liquids. In meeting this specification, “dew point” plants, are commonly applied. Dew point plants target recovery of hydrocarbons, mainly heavier hydrocarbons. As with NGL recovery, quick cycle units, refrigeration or Joule-Thompson expansion plants can also be applied.
An alternate means to remove the heavy hydrocarbons from natural gas is to use a silica gel adsorbent in so called “quick cycle units” wherein the adsorbent has an affinity for heavy hydrocarbons, typically C6 and heavier components. In such a means, the natural gas containing heavy hydrocarbons is passed through the bed of silica gel to trap C6+ hydrocarbons. Regeneration is typically done by passing a pressurized and/or heated stream of natural gas feed or product gas through the adsorbent bed. After cooling the heavy hydrocarbons, contained in the effluent from the regeneration process, can be condensed as a liquid product and removed.
The relationship in value of natural gas to natural gas liquids is complex and the prices, while related, do fluctuate. Almost always, the components are more valuable as a liquid than as a gas and a typical increase in value is about 1.5× the value in the pipeline. The extraction of liquids is the main business of mid-stream processors.
The present assignee has developed processes for the recovery of hydrocarbons from natural gas utilizing pressure swing adsorption with Molecular Gate® sieves. These processes are described in U.S. Pat. No. 6,444,012, issued Sep. 3, 2002, and U.S. Pat. No. 6,497,750, issued Dec. 24, 2002. In the former application, the PSA process involves initially adsorbing C3+ hydrocarbons from a natural gas stream in a first PSA unit containing a hydrocarbon-selective adsorbent to produce a first product stream comprising methane, nitrogen and reduced level of hydrocarbons relative to the feed. The first product stream is then directed to a second PSA adsorption unit containing a nitrogen selective adsorbent (Molecular Gate®) so as to adsorb nitrogen and produce a second product stream enriched with methane. Recovery of the hydrocarbons can be achieved by desorbing the first adsorbent with the methane product stream. In this way, the heat value of the C3+ hydrocarbons is recaptured in the methane stream. The latter application is directed to a process of separating nitrogen from a feed natural gas stream in a first PSA unit containing a Molecular Gate® nitrogen-selective adsorbent to form a methane product stream, directing the tail gas from the first PSA unit to a second PSA unit containing a methane selective adsorbent so as to recover methane from the tail gas to form a nitrogen rich product stream and a tail gas stream comprising hydrocarbons and refrigerating the hydrocarbon-containing tail gas so as to knock out the C3+ hydrocarbon liquids. The methane is then recycled to feed.
Typical pipeline specifications for H2S are 4 ppm and 2% for CO2. Liquid natural gas (LNG) facilities generally require the near complete removal of these acid gases since the acid gases freeze at the temperatures of LNG. U.S. Pat. No. 4,702,898, issued to Grover discloses a process for the removal of acid gases from mixtures which utilizes an alkaline scrubbing solution to remove the acid gases, e.g., carbon dioxide, from the gas mixtures. In addition to acid gas adsorption, solid adsorbents, e.g., molecular sieves, can be employed for the further removal of carbon dioxide depending upon the ability of the liquid adsorption system to remove carbon dioxide and upper limits on the permissible carbon dioxide concentration. For example, adsorption is often employed when it is necessary to substantially remove carbon dioxide to levels of about 50 to 200 ppmv carbon dioxide, such as is typically required in liquefaction or deep ethane recovery. In some instances, it can be desirable to eliminate the liquid carbon dioxide adsorption unit and perform the carbon dioxide removal by molecular sieve adsorption alone, e.g., for purification where bulk carbon dioxide removal is not required (i.e., natural gas feeds low in acid gas components).
As discussed above, a particular disadvantage of the amine solvent treatment for removal of acid gases is that the solvents are used as a mixture with liquid water, and thus, the natural gas product from the amine treatment plant is saturated in water vapor. This requires downstream dehydration, which mostly commonly uses glycol solvents. For LNG plants extremely low water dew points are required and molecular sieve (or other adsorbents) are commonly applied, sometimes downstream of a glycol unit where the glycol serves for bulk water removal.
U.S. Pat. No. 3,841,058, issued to Templeman, discloses a method of purifying natural gas or the like to render it suitable for liquefaction. The method consists essentially of adsorbing water and methanol from a stream of natural gas containing water, methanol and carbon dioxide in a first bed of an adsorbent material and subsequently adsorbing the carbon dioxide in a second bed of adsorbent material. The first adsorber bed is regenerated by passing a gas therethrough at an elevated temperature, i.e., thermal swing adsorption. The second adsorber bed is regenerated by reducing the pressure within the bed and also by passing a gas therethrough at a low temperature to displace desorbed carbon dioxide from the adsorber bed, i.e., a pressure swing adsorption cycle. The patent discloses that the adsorption effluent gas from the first adsorber bed can be cooled to subambient temperatures to increase the adsorptive capacity of the molecular sieves for carbon dioxide.
The method disclosed in above-identified U.S. Pat. No. 3,841,058, however, does not provide an adequate solution to the problem of removing water and carbon dioxide prior to low temperature LNG processing. More specifically, because the second adsorber bed is regenerated by pressure swing adsorption, there is inherently less hydrocarbon recovery due to the fact that pressure swing cycles are usually operated at a shorter cycle time than thermal swing cycles, e.g., minutes versus hours, and hence, the hydrocarbon feed gas which remains in the void space after the adsorption step is terminated is lost in the desorption effluent stream when the adsorber bed is depressurized. In addition, because thermal swing adsorption cycles typically provide more complete regeneration than is generally possible with pressure swing cycles, higher residual carbon dioxide levels are present on the adsorbent subjected to pressure swing regeneration. The higher residual levels cause higher levels of carbon dioxide in the product gas since the concentration of carbon dioxide in the product gas is in equilibrium with the carbon dioxide adsorbed on the adsorbent in the effluent end of the adsorber bed. In order to keep the carbon dioxide content of the adsorbent low in the effluent end of the adsorber bed it is necessary to reduce the cycle time, however, reduced cycle times contribute to the recovery losses described above. Hence, the above-identified patent describes a process that is deficient due to the use of the pressure swing adsorption cycle in the second adsorber bed as compared to a thermal swing cycle.
Adsorption units using silica gels are used in a wide variety of applications. In the natural gas industry, one example application for silica gels is in adsorption drying. The use typically employs two or more adsorber vessels filled with adsorbent to remove water from natural gas, and produce a dry natural gas product. When the silica gel adsorbent is saturated with water, it is commonly regenerated using a portion of the feed gas or dry product gas, heated to high temperature (typically 300° to 500° F.) to strip the previously adsorbed water off the adsorber bed. Various flow schemes for recycling this regenerated stream, now containing water, exist in the industry.
However, a more common process for dehydration in the natural gas industry is the glycol dehydration process, in which a stream of glycol, for example triethylene glycol, is contacted against the incoming natural gas stream. The glycol solvent extracts water from the stream and a reduced water product is produced. The rich glycol stream is subsequently regenerated by pressure reduction and heating, after which it is pumped back as a lean stream to continue its water removal service.
Another common application for silica gel adsorbents is in quick cycle heavy hydrocarbon removal units. In this application, heavy hydrocarbons are adsorbed from natural gas product meeting hydrocarbon dew point requirements. As with water removal, the silica gel adsorbent, now saturated with heavy hydrocarbons, is regenerated at high temperatures, typically 500° F., using a portion of the feed stream or the hydrocarbon reduced product stream.
Another example of an application for silica gel in natural gas processing is its use to remove water vapor and heavy hydrocarbons upstream of a membrane unit used to remove CO2. Such CO2 removal membrane units operate by selective permeation of CO2 from high pressure to low pressure across a polymeric membrane. Such membranes will lose treating capacity over time due to exposure to heavy hydrocarbons and silica gel adsorption processes are commonly used for the removal of both water and heavy hydrocarbons. Such membrane units are generally used only as bulk CO2 removal devices and will commonly be followed by amine processing for final CO2 removal. In this configuration, the first stage treatment will be a silica gel dew point unit to remove heavy hydrocarbons and water, followed by a membrane unit for bulk CO2 removal, followed by an amine system for acid gas removal. The amine unit in this application re-introduces water vapor back into the product natural gas and, thus, downstream dehydration is subsequently required.
It is an object of the present invention to provide a novel and economically beneficial natural gas purification system for the adsorptive removal and recovery of heavy hydrocarbons (C4+ hydrocarbons, or more preferably C6+ hydrocarbons), water, and acid gases. The application of the integrated process of the present invention results in an improved process for the removal of heavy hydrocarbons, carbon dioxide, hydrogen sulfide, and water from raw natural gas.